Heat-Recovery Steam
Generators:
Understand the Basics
Gas turbines with heat-recovery - steam
By understanding
how gas-turbine
heat-recovery steam
generators differ
from conventional
steam generators,
engineers can
design and operate
HRSG systems that
produce steam
efficiently.
V. Ganapathy,
ABCO Industries
32 •
AUGUST 1996 •
generators(HRSGs) can be found in
virtually every chemical process
industries (CPI) plant. They can be
operated in either the cogeneration mode
or the combined-cycle mode (Figure 1).
In the cogeneration mode, steam produced
from the HRSG is mainly used for
process applications, whereas in the
combined-cycle mode, power is generated
via a steam turbine generator.
Gas turbines have several advantages as a
power source: they can be started up
quickly; they come in packaged modules,
with power outputs ranging from 3 MW
to 100 MW, that can be easily assembled
and erected; they have high efficiencies of
25% to 35% (on a lower heating value
[LHV] basis); and they require little or no
cooling water. Recent developments include large-capacity units of up to 250
MW, with low emission characteristics
(less than 10 ppmv NOx), as well as high
combustor operating temperatures (in the
range of 2,200°F), which results in efficiencies higher than 35%; the exhaust gas
temperature is also higher, which helps to
generate high-pressure/high-temperature
superheated steam, making the Rankine
cycle efficient.
The HRSG forms a major part of the
steam system. In the combined-cycle
mode, the efficiency of the combined gasturbine-plus-HRSG system can reach 5560% (LHV basis) with today's advanced
machines, while in the cogeneration
mode, system efficiency can be as high as
75-85%.
CHEMICAL ENGINEERING
The HRSG generates steam utilizing the
energy in the exhaust from the gas
turbine. However, some plants also have
the capability of producing steam when
the gas turbine is shutdown. This is done
using a separate forced-draft fan along
with a burner to generate hot gases, which
are then used to generate steam. An
isolating damper system (also called a
bypass damper) with seal air fans is re quired in these units to ensure that hot
gases do not leak to the fan when the gas
turbine is running and that maintenance
can be performed on the gas turbine when
the fresh air fan is operating. Bypass
dampers are also used in some units to
ensure that the gas flow to the HRSG can
be modulated in order to match steam
generation with steam demand. However,
if fresh air firing is not used, an isolating
damper is not required.
Recent trends in HRSG design include
multiple-pressure units for maximum energy recovery, the use of hightemperature superheaters or reheaters in
combined cycle plants, and auxiliary
firing for efficient steam generation. In
addition, furnace firing is often employed
in small capacity units when the exhaust
gas is raised to temperatures of 2,4003,000°F to maximize steam generation
and thus improve fuel utilization.
This article highlights some of the basic
facts about gas turbine HRSGs. This
information can help plant engineers,
consultants, and those planning cogeneration projects make important decisions about the system and performance
related aspects.
HRSG temperature profiles and
steam generation
The starting point in the engineering of
a HRSG is the evaluation of its steam
generation capability and gas and steam
temperature profiles. For a
conventional fired steam generator, one
can assume a desired steam flow rate
and exit gas temperature and then fire
the necessary amount of fuel to meet
the steam demand. A HRSG behaves
differently due to the low inlet gas
temperature (900-1,050°F in the unfired
mode) and the large gas/steam ratio.
Arbitrarily assuming an exit gas
temperature or steam generation rate
can lead to "temperature cross situations" (discussed below).
Figure 2 shows the typical gas and
steam temperature profiles in a HRSG
consisting of a superheater, evaporator,
and economizer operating at a single
pressure. Because the gas temperature
entering the HRSG is low (900 -1,050°F
in unfired units), the steam generation
will also be lower than in conventional
steam gen erators for the same gas flow.
(Re
CHEMICAL ENGINEERING PROGRESS • AUGUST 1996
• 33
member that conventional steam generators start out at 3,200°F or so, the
adiabatic combustion temperature of
the fuels used.) Hence, the economizer duty in the HRSG will also be low,
leading to a high exit gas temperature. Also (again unlike in a conventional steam generator), the effect of
steam pressure is significant - the
higher the steam pressure, the higher
the exit gas temperature from the
evaporator and the lower the steam
generation rate, leading to a smaller
duty in the economizer and a higher
exit gas temperature. This is the reason for considering multiple -pressure
units, as well as deaeration steam
coils and condensate heaters in
HRSGs operating at high pressures.
Two variables that directly affect
steam production and the gas and
steam temperature profiles are the
pinch point and the approach point
(Figure 2) (1). The pinch point is the
difference between the gas temperature leaving the evaporator and the
temperature of saturated steam. The
approach point is the difference between the temperature of saturated
steam and the temperature of the
water entering the evaporator.
Selection of these two variables also
affects the size of the superheater, the
evaporator, and the economizer.
Based on the sizes of evaporators that
can be built and shipped economically, the pinch and approach
points for unfired HRSGs are usually
in the range of 15°F to 30°F. (If one
specifically wants to generate less
steam, such as in a multiple-pressure
HRSG generating more low-pressure
steam than high-pressure steam, then
a larger pinch and approach may be
used.)
Pinch and approach points are selected for a particular case or exhaust
gas condition called the "design
case." Unlike in a conventional steam
generator, where the steam demand
drives the design case, in a HRSG
steam production is affected by the
conditions of the exhaust gas leaving
the gas turbine (such as flow rate,
temperature, and gas analysis) and
34 •
AUGUST 1996 •
entering the HRSG. Also, these parameters vary with ambient conditions,
elevation, gas turbine load, and fuel
fired. Hence, the design case could be
60°F ambient condition at 100% load
of the gas turbine, or any other
accepted gas inlet parameters.
Using exhaust gas parameters at this
condition, one arrives at the design
temperature profile, which forms the
basis for sizing the HRSG. The HRSG
is then designed, or sized, once the
pinch and approach points are selected
- that is, the surface areas are
determined indirectly.
Once selected, the pinch and approach
points will vary if gas flow and exhaust
gas temperature vary. These cases are
called "off-design" cases. For example,
at different ambient conditions and gas
turbine loads, one can have different
exhaust gas parameters, or one may
have to burn
CHEMICAL ENGINEERING PROGRESS
auxiliary fuel to generate a desired
quantity of steam. There is only one
design case, but several off-design
cases.
Prudent engineering calls for the
pinch and approach points to be es tablished in the unfired mode (2, 3)
rather than in the fired mode, for several reasons:
1. Designs that can be physically and
economically shipped can be established if pinch and approach points
are chosen in the range suggested
(Figure 2) in the unfired mode at the
design ambient conditions.
2. A HRSG simulation approach is
required to evaluate the pinch and
approach points at fired conditions or
at different ambient conditions (2, 3).
If the pinch and approach were selected in the fired mode (which is not
recommended), it is likely that the
pinch point in the unfired mode could
be too low, resulting in a huge, unwieldly, and uneconomical HRSG.
Also, a low approach point in the
fired mode could result in steaming
in the economizer under unfired
conditions. Economizer steaming
should be avoided, as it results in
operational problems such as
vibration, water hammer, and
possible deposition of salts in the
economizer tubes, with the ultimate
result being reduced performance.
3. If a superheater is used, it is
not possible to estimate the degree
of oversizing if the pinch and
approach are selected in the fired
mode. If the steam temperature is to
be maintained over a wide load
range, it is likely that the steam
temperature will be lower than
desired under unfired conditions. If
pinch and approach points along
with the desired steam temperature
are selected in the unfired mode,
then the steam temperature can
certainly be maintained under fired
conditions and can be controlled
using attemperation or other means.
A HRSG simulation program
(such as the one developed by the
author (2)) may be used to simulate
the
design
and
off-design
performance of single, multiplepressure unfired and fired HRSGs
(/). Simulation gives a good idea
of what the HRSG can do at
different gas inlet conditions, and
can help one optimize temperature
profiles and HRSG configurations
and evaluate HRSG performance
with
different
gas
turbines.
Simulation can also help one
evaluate the effects of the exhaust
gas analysis, which is important in
steam-injected gas turbines, because
gas specific heat and duty are
impacted by gas analysis.
of steam leaving the superheater (ts2),
and steam pressure (Ps). Assuming a
reasonable pressure drop in the superheater, we can determine the saturation
temperature ( t s) at the evaporator.
Once the pinch point is selected, we
know the temperature of the gas leaving the evaporator ( t g3) and the approach point gives the temperature of
the water leaving the economizer (tw2),
since the saturation temperature is
known. The heat loss (hl) ranges from
2% in small HRSGs to about 0.5% in
large units. Methods of estimating heat
losses are outlined elsewhere (2).
Considering the energy balance
across
the
superheater
and
evaporator (Figure 2), the energy
absorbed by the superheater and
evaporator is given by:
Q1.2 = Wg C pg( tg1 - tg3 ) (hl) =
Wsd[(h s2 - h w2 )
+ (bd)(h f- h w 2)]
(1)
Since t g 1 and t g3 are known, Q 1 2 can
be computed and the design steam
flow (Wsd ) can be determined. The
superheater duty is:
Q1
= Wsd (h s2 - h v)
= Wg C p g ( t g l - tg2 ) (hl)
(2)
From above, the temperature of the gas
leaving the superheater ( t g2 ) can be
determined, since all the other data are
known.
The economizer energy balance
gives:
Q3 = Wsd (h w2 - h w1 )(1 + bd)
= W g Cpg ( tg3 - tg4 ) (hl)
(3)
The gas temperature leaving the
economizer ( t g4) can be obtained from
this. Thus, the complete gas/steam
profiles and steam generation rate for the
design case can be determined by
assuming the pinch and approach points.
In addition, once the pinch and
approach points are selected, the logmean temperature differences ( ∆T) at
Design temperature profile
the various surfaces are fixed. Since
calculatio ns
from basic heat-transfer principles
The starting point for determining surface area is given by S = QIUAT,
gas and steam temperature profiles and the surface areas of all the compo
steam generation is the assumption of
pinch and approach points, as
discussed above. The values that are
known are gas flow rate (Wg, gas
temperature at HRSG inlet ( t g1 ), feed
water temperature (tw1), temperature
nents, such as the superheater, evaporator, and economizer, are fixed once
U is computed. (To calculate U one
should have such mechanical data as
tube size, fin density, tube pitch, etc.)
But if U is not known, US is, which
indirectly fixes the surface areas.
Now, if we want to know how the
HRSG behaves at different gas conditions, we have to perform off-design
calculations and use the "surface areas"
we have indirectly established. It may also
be noted that we are using a pinch point
of about 15-20°F, which results in a low
AT in the evap orator and thus the need
for large surface area. (The pinch point in
a con ventional steam generator could
range from 150°F to 400°F, so the ∆T is
much higher and the required surface
area much less.) This is why extended
surfaces are a must in HRSGs.
Don't select exit gas
temperatures arbitrarily
The right way to evaluate the design temperature profile is to assume
pinch and approach points and perform the calculations outlined above.
The exit gas temperature ( t g4 ) is determined as shown above.
What happens if we try to assume
a value for t g 4 ? From Figure 2, considering the heat balance across the
superheater and evaporator and neglecting blowdown, we have:
Wg Cp g( t
g 1 - t g 3 ) (hl)
= Ws d(h s2 - h w2 )
(4)
Also, considering the complete
HRSG:
Wg Cpg (tg l - tg4 )(hl)
= Wsd(h s2 – h w1 )
(5)
Dividing Eq. 4 by Eq. 5 and neglecting the effect of specific heat, we
have:
(t g 1 - t g3 )/(tg 1 - t g4 )
= (h s2 - h w 2)/(hs 2 – h w1 )
= K
(6)
For steam generation to occur, two
conditions must be met:
tg3 > ts
tg 4 >twl
CHEMICAL ENGINEERING PROGRESS • AUGUST 1996
• 35
If either condition fails, a temperature cross (1,600 - 512)/(1,600 –tg4) = 0.7728,
situation results, meaning that the HRSG
or tg4 = 192°F, which is below the
parameters are invalid and must be selected feed water temperature of 230°F.
again. This is why we cannot arbitrarily
This, too, is an invalid temperature
select pinch and approach points and the
profile. With a much higher pinch
exit gas temperature.
point we could have obtained tg4
Calculations for t have been carried out at above 230°F. This illustrates why
various steam conditions for a typical gas
pinch and approach points are best
turbine and the results are presented in
selected in the unfired mode, having
Table l. It may be seen that as the steam
values in the range suggested in Figpressure increases, the exit gas temperature ure 2, to ensure valid temperature
increases. Also, as the steam temperature
profiles. Simulation can also help deincreases at a given pressure, the amount of termine valid conditions.
steam generated decreases for a given pinch
point; this results in a decrease in the
Evaluating
economizer duty, thus increasing the exit
off-design performance
gas temperature. (The calculations are based We have seen how the "design
on a gas inlet temperature of 900°F, feed
temperature profile" is arrived at. Using
water temperature of 230°F, pinch point of simulation, one can predict HRSG
20°F, and approach of 15°F.)
performance at any other gas inlet
Let us now see that an exit gas temperature conditions or steam parameters. This
of 300°F, at conditions of, say, 600 psig and approach is discussed elsewhere (1,2).
750°F, cannot be achieved. Using data from
the steam tables, K = 0.7728 at these conditions. From Eq. 6, (900 –tg3)/(900 - 300) =
0.7728, or tg3 = 436°F. This is below the
saturation temperature of 492°F, which is
not a valid temperature profile - hence, we
say that temperature cross has occurred.
Now let us see what happens if we select the
pinch point in the fired mode with a gas
inlet temperature of 1,600°F. Let us assume
a 20°F pinch at the same pressure and
temperature conditions as above.
Using Eq. 6,
g4
5•
AUGUST 1996 •
CHEMICAL ENGINEERING PROGRESS
In simple terms, the factor US is obtained
using the equation Q/∆T for each
surface in the design case. Then in the
off-design case, the values of US are
corrected for the effects of gas flow,
temperature, and composition. Then, the
energy transferred across each surface is
obtained through an iterative process
using the following equation (after first
assuming a steam flow rate to begin):
Q = WgCpg(tgi - tgo)
= Ws(ho -hi)
= US∆T
(7)
The total energy transferred across
each surface is computed, and the actual steam generation rate (Ws) is obtained from the sum of ΣQ/(∆h) for
all the surfaces. This information is
then used to correct the assumed
steam flow.
The problem gets more complicated if
there are several modules, and gets
complicated further still if auxiliary firing
is used to generate the desired steam flow
rate in a particular module. Simulation
software, which performs these complex
calculations in minutes, comes in handy
in these s ituations.
HRSG design features
The HRSG generates steam, the quality
and quantity of which depend on the
flow and temperature of the exhaust gas
entering it. Large cogeneration and
combined-cycle plants
generate high-pressure/high-tempera ture superheated steam (600-1,500 psig
at 650-950°F), while small ca pacity
plants (10-MW gas turbines and below)
may generate low-pres sure saturated
steam (100-300 psig). The superheated
steam temperature in a HRSG is
controlled using spray desuperheaters
as in conventional boilers. Steam
temperature varies with gas inlet
conditions, so performance should be
verified at various off-design cases.
Multiple-pressure steam generation is
employed in cases where the exit gas
temperature from single-pressure-level
generation would be considered too
high or uneconomical.
There are three types of HRSGs:
unfired, supplementary-fired, and exhaust-fired (Figures 3-5). This is not a
rigid classification, but it is widely used.
Table 2 shows the main features and
the typical steam outputs that can be
expected for each of the three types.
Figure 4b also shows a freshair-firing
system, where a supplemen tary-fired
HRSG is operated using air from a fan,
a situation that arises, for example,
when the gas turbine trips or is shut
down for maintenance. Fig ure 4c shows
a typical duct burner for a
supplementary-fired HRSG.
Unfired and supplementaryfired HRSGs
The HRSG consists of single- or
multiple-pressure modules depending
upon the degree of energy recovery
desired. A simulation of the tempera ture profiles must be performed (I)
before designing the steam system for a
given application.
Unfired and supplementary-fired
HRSGs are similar in appearance and
constru ction, both being convective
designs. The units are internally insulated with ceramic-fiber insulation with
an alloy steel liner to hold the insulation
in place. The insulation thickness
ranges from 4-6 in. inunfired units to 810 in. in supplemen tary-fired units.
Roughly two-thirds of the HRSGs
purchased today are unfired due to their
low first cost.
CHEMICAL ENGINEERING PROGRESS 9 AUGUST 1996 • 37
Extended surfaces are widely used in the
superheater, evaporator, and
economizer. This is because a large
surface area is required in these systems
as a result of the low pinch and
approach points and the low logmean
temperature differences at the various
heating surfaces. Extended surfaces
make the HRSG design very compact.
And, lower gas pres sure drops can be
achieved with extended surfaces than
with bare tubes (Table 3) (2).
For evaporators and economizers with
clean gas streams, such as exhaust from
natural-gas -fired and dis tillate-oil-fired
gas turbines, fin densities of 4 to 5
fins/in. are reco mmended. Fin height
can vary from 0.5 to 1 in. Fin thickness
is typically from 0.05 to 0.075 in.
A low fin density is recommended for
superheaters due to their low tube-side
heat-transfer coefficient (3). Using a
high fin density when the tube-side
coefficient is low offers no added
benefit. The use of fins, in gen eral,
increases the tube wall and fin tip
temperatures and the heat flux inside the
tubes. When the tube-side co efficient is
low, the temperature drop across the
tube-side film is naturally high, resulting
in high tube wall and fin tip
temperatures even without fins.
In fired units, a combination of bare and
finned tubes is used to en sure that the
tube wall and fin tip tem -
7•
AUGUST 1996 •
peratures remain safely within limits.
The first few rows of tubes near the
high-gas-temperature zone use bare
tubes, and subsequent tube rows,
where the gas is cooler, have extended
surfaces.
Surface areas can be misleading,
particularly when finned tubes are used.
The higher the fin density and the ratio
of external-to-internal tube surface
area, the lower the gas-side heattransfer coefficient and hence the lower
the overall heat-transfer co efficient
(Figure 6) (2, 4). Thus, a
CHEMICAL ENGINEERING PROGRESS
HRSG with surface area that is 100200% more than that of another design
with a lower fin density can transfer the
same duty. Therefore, one should look
at the product of overall heat -transfer
coefficient times surface area (US)
instead of surface area alone.
Table 4 illustrates the effects of fin
geometry on superheater performance
(3, 4). For example, a superheater can
transfer the same duty with significantly different surface areas - the
surface area in case 2 is more than
double the surface area in case l, yet
the duty (or energy transferred) is essentially the same. This is because of
the poor fin configuration in case 2 due to the higher heat flux inside the
tubes with the higher fin density, the
tube wall and fin tip temperatures in
case 2 are much higher than in case 1.
Hence, the use of excess surface has
negative implications, too. Comparing cases 2 and 3 illustrates how more
duty is transferred with a lower surface area simply by selecting optimum fin configuration. Thus, engineers and purchasing managers
should not make decisions using a
spreadsheet that shows only the surface areas of different designs.
Rather, a good evaluation should include the product of overall heattransfer coefficient (on an external
surface area basis) and surface area.
A supplementary-fired HRSG has a
duct burner (Figure 4c) located upstream. A duct burner typically has
a rectangular cross-section and fits
into the ductwork carrying the
exhaust gases. It consists of vertical
or horizontal grids with holes that
admit fuel
(such as natural gas and distillate oil)
into the exhaust gas stream.
Generally, no additional air is used,
except when the exhaust gas is
injected with large quantities of
steam, which reduces the amount of
oxygen available for combustion. In
these cases, a small fan (called an
augmenting air fan) is also included
with the burner.
The duct burner raises the exhaust gas
temperature from about 1,000°F to a
maximum of 1,700°F in HRSGs with
insulated casings and up to 2,400°F in
HRSGs equipped with water-cooled
furnaces. The gas pressure drop across
the duct burner is low (on the order of
0.5 in. w.c.). This is important because
each additional 4 in. w.c. gas pressure
drop in the HRSG decreases the gas
turbine power output by about I %.
In large capacity units for combinedcycle plants, reheaters are installed in
addition to superheaters to improve the
Rankine cycle efficiency. Unlike in a
Rankine cycle system based on a
conventional steam generator, where
the condensate is heated in external
steam-to-water heat exchangers using
steam extracted from the steam
turbine, in a gas turbine HRSG the
condensate or make-up water is heated
in the HRSG itself to improve the
efficiency of energy recovery.
Deaeration steam may also be generated in the HRSG for the same reason.
Thus, it is not unusual to see several
modules in a HRSG. Multiple pressurelevel steam generation,
CHEMICAL ENGINEERING PROGRESS
AUGUST 1996
• 39
which increases the efficiency of en ergy
recovery, is common in unfired and
supplementary-fired HRSGs.
Exhaust-fired HRSGsThe exhaustfired HRSG (Figure 5), in which the
firing temperature ranges from 1,700°F
to 3,000°F, uses a completely watercooled furnace to contain the flame,
since the temperature could approach
the adiabatic combustion temperature.
The burner used is typically a register
burner with a windbox, although a duct
burner may be used up to 2,400°F. The
gas turbine exhaust is used as hot air
for combustion. In certain plants
overseas, even solid fuels such as coal
have been fired in these boilers using
register burners.
The gas pressure drop across the
register burner is high (about 4-6 in.
w.c.). The HRSG is typically a single
9•
AUGUST 1996 •
pressure unit in these systems, as the
exit gas temperature can be brought
down to a low level (on the order of
300°F), unlike in an unfired or supplementary-fired HRSG, which has a
high exit gas temperature if a singlepressure system is used.
Due to the high gas temperature
entering the HRSG, the design is likely
to consist of more bare tubes than
finned tubes. A radiant furnace is
required to cool the gases before they
enter the superheater or convective
sections.
Auxiliary firing and
system efficiency
Typical gas turbine exhaust contains 1315% oxygen by volume. This is
adequate to fire additional fuel in the
burner to raise the exhaust gas
temperature to about 3,000°F. The relationship between oxygen availability
CHEMICAL ENGINEERING PROGRESS
and natural gas or fuel oil input is (3):
Q = 58.4W gO
(8)
where W g is the exhaust gas flow in
lb/h, O is the oxygen consumed in
%vol., and Q is the burner heat input in
Btu/h (LHV basis).
For example, if the exhaust gas
conditions are 150,000 lb/h at 1,000°F
with 15% oxygen, the energy required
to raise the gas to 1,700°F is
approximately Q = (150,000)(0.3) x
(1,700 - 1,000) = 31.5 MM Btu/h; the
oxygen consumed during com bustion
will be: O = 31,500,000
[(150,000)(58.4)] = 3.6%. Thus, the
exhaust gas still contains more than
11.4% oxygen.
A HRSG simulation program has been
used to evaluate the efficiency of
supplementary firing on HRSG per formance, and the results are present ed
in Table 5 and Figures 7 and 8. As
the amount of firing increases, the efficiency of the system (as defined by
ASME PTC 4.4 (S)) also increases.
Note that the fuel utilization in the
HRSG is nearly 100%. The additional
boiler duty to generate 60,000 lb/h of
steam is 59.90 - 22.67 = 37.23 MM
Btu/h and the fuel added is 37.60 MM
Btu/h (LHV basis). Thus, all of the fuel
energy goes into generating steam,
making the fuel utilization 100%,
compared to the efficiency of a
conventional steam generator of about
90%. There are two reasons for this:
l. We know from basic combustion
principles that in a conventional steam
generator, as the excess air increases,
the efficiency decreases. This
CHEMICAL ENGINEERING PROGRESS • AUGUST 1996 • 41
is because the additional air must be
heated from ambient conditions to the
exit conditions. In a HRSG, on the
other hand, the amount of excess air is
reduced by firing only fuel in the
exhaust gas without adding air.
2. The exit gas temperature in a
single-pressure HRSG decreases as
the firing temperature increases. In a
conventional steam generator, the
gas/steam ratio remains nearly constant at about unity at all loads,
where as in a gas turbine HRSG, it
decreases as steam generation
increases. This results in a larger heat
sink at the economizer and hence a
lower exit gas temperature. Note that
in a HRSG, the gas flow remains
nearly the same at all steam
generation levels.
Therefore, engineers should first plan
to generate additional steam in the
HRSG before using conventional
steam generators (6, 7). As discussed
earlier, unfired and supplementaryfired HRSGs do not differ much except for changes in steam drum size,
insulation thickness, valve sizes, and
so on. Hence, it may be economical to
consider these designs for firing up to
1,300-1,500°F to maximize steam
generation at a high efficiency. The
furnace-fired HRSG requires a
completely different design with
completely water-cooled membranewall furnaces, so a detailed cost
evaluation is needed to determine the
economic viability of this type of
HRSG.
Natural vs. forced circulation
Natural-circulation HRSGs (as shown
in Figures 3-5) are common in the
U.S. In Europe, forced-circulation
units (Figure 9) are more prevalent. In
natural-circulation HRSGs, the tubes
are vertical and gas flows horizontally. The widths of the various
modules are limited by shipping
considerations. Thus, large HRSGs
may have modules 12 ft wide and 3050 ft tall. Downcomer pipes carry the
hot saturated water to the bottom of
the evaporator modules and riser pipes
carry the steam/water mixture to the
external steam drum, where
42 •
AUGUST 199 6 •
files, casing design, use of extended
surfaces, and surface area require ments are similar between naturaland forced-circulation units.
separation occurs. Saturated steam is
then taken to the superheater.
In forced-circulation HRSGs, the tubes
are horizontal and gas flow is vertical.
This configuration minimizes the use
of land space. The cross-sectional area,
though, is the same as in naturalcirculation systems.
Pumps maintain circulation of the
water/steam mixture through the
evaporator tubes, which results in an
additional operational expense. Failure
of the pumps can cause shutdown and
possibly evaporator tube failure.
Keep in mind that the heat flux in side
finned tubes is several times that in a
comparable bare tube. Thus, fired
HRSGs must be designed with care to
prevent overheating of the tubes. In
general, horizontal tubes cannot
tolerate heat fluxes as high as vertical
evaporator tubes can because in the
latter gravity assists in providing good
wetting of tube periphery. In addition,
steam bubbles formed during boiling
tend to concentrate on the top portion
of the horizontal tubes, while water
occupies the lower portion. This results
in a varying temperature profile across
the tube periphery due to the different
heat-transfer coefficients of water and
steam, which leads to higher thermal
stresses.
Other aspects of HRSG design, such
as gas/steam temperature pro
CHEMICAL ENGINEERING PROGRESS
Improving HRSG efficiency
Several options for improving energy
recovery, even in a single-pressure
steam system, are illustrated in Figure
10.
Make-up water or condensate can be
heated in the HRSG itself (Figure
10a). This reduces the amount of
steam required for deaeration, improving the overall efficiency. If sulfuric acid vapor is present in the exhaust gases, the condensate temperature should be no lower than the acid
vapor's dew point to prevent condensation of the corrosive vapors on the
tube (4). This condensate heater option is generally used in natural-gasfired systems that do not contain acid
vapors. Still, the water temperature
entering the exchanger should be
above the water vapor's dew point to
prevent water condensation on the
tubes.
The second option is to generate lowpressure saturated steam or deaeration
steam in the HRSG itself using a lowpressure evaporator (Figure 10b). This
type of system is recommended if
there is a possibility of acid vapor
condensation, since the steam
saturation temperature can be
maintained above the acid's dew point.
However, it is more expensive than
the condensate heater option due to
higher surface area requirements and
the need for a drum, instrumentation,
and controls. The exit gas temperature
from the HRSG will naturally be
higher than the saturation temperature
of steam, whereas in the pre vious
option, it could be much lower.
The third option is to preheat the
make-up water in a heat exchanger
before it enters the deaerator, while
simultaneously cooling the feed water
before it enters the economizer (Figure 10c). The economizer requires a
larger surface area, but this is an economical option compared to the
deaerator.
Condensing heat exchangers have
also been used in some projects.
Polytetrafluoroethylene (PTFE; e.g.,
Teflon) or similar corrosion-resistant
material is used as a coating on the
tubes to prevent corrosion from acid
condensation. In such cases, the
make -up water can enter the heater as
cool as 60-80°F.
Another option for lowering the
exhaust gas temperature is to
circulate more water than necessary
through the economizer and
recirculate the excess to the deaerator
in order to reduce the deaeration
steam requirements (Figure 1Od).
Some plants, depending upon the
steam system and the quantity and
temperature of make-up water re quired, may use a combination of
these methods.
Evaluating operating data
HRSGs often operate under different
exhaust gas conditions and steam
parameters than the design conditions
- for example, if the ambient
temperature or gas turbine load is
different from what was selected for
design of the HRSG. The questions
then arise as to whether the HRSG is
operating satisfactorily or not, and
how the operating data
CHEMICAL ENGINEERING PROGRESS 9 AUGUST 1996
• 43
range of 2-4 in. w.c., which must be
considered in the overall design and
performance evaluation.
can be reconciled with any performance
guarantees.
One way to answer these questions
is through HRSG simulation. One can
use the operating data to simulate the
design pinch and approach points, and
then use this information to predict the
HRSG off-design performance at the
conditions specified in the proposal or
guarantee. A comparison between the
two sets of data can confirm whether
or not the HRSG original design is
adequate (8).
Use of catalysts
With stringent environmental regulations for carbon monoxide and nitrogen oxides, the use of catalysts for
controlling emissions is becoming
commonplace. Steam and water injection and modifications to the gas
turbine combustor can reduce NOx
levels to 30-40 ppm. However, some
states require that NO, be reduced
13 •
AUGUST 1996 •
further to 9-15 ppm. Catalysts, in the
form of selective catalytic reduction
(SCR) systems (9), can be used in the
HRSG to achieve this lower emission
level.
Catalyst performance is affected by gas
temperature at the catalyst. Catalysts
operate efficiently over a narrow range
of gas temperatures. For NOx catalysts,
the gas temperature range is typically
600-750°F; for CO catalysts it is 9001,200°F. The catalyst supplier specifies
this temperature window, which
depends on the materials used. In order
to achieve temperatures within this
window at all loads of the HRSG, the
heat-transfer surfaces may have to be
split to find a good location for the
SCR (Figure 11).
Provision should be made for an
ammonia injection grid upstream of the
NOx catalyst. The catalyst also has a
high gas pressure drop, in the
CHEMICAL ENGINEERING PROGRESS
Turbine exhaust
characteristics
Two important variables that affect flow
rate and temperature of the gas turbine
exhaust are ambient temperature and
load, as mentioned earlier. These
parameters, in turn, affect HRSG
performance. At higher ambi ent
temperatures, the exhaust gas flow is
lower and the exhaust gas temperature is
higher, and vice versa. As the gas turbine
load decreases, the exhaust gas
temperature also decreases but the mass
flow does not vary much.
As a result of the variations in exhaust
gas flow and temperature, the HRSG
steam flow and temperature will also be
affected (Figure 12). Therefore, engineers
should analyze HRSG performance at
various cases and ensure that the plant
performance is not impacted by the
varying steam production in the HRSG.
Supplemen tary firing of the HRSG, as
well as steam and water injection in the
gas turbine, may have to be considered to
ensure steady steam production.
Steam injection is becoming more
widespread. In addition to controlling
NO, emissions from the gas turbine
combustor, it also increases the gas
turbine power output as well as the
HRSG output. This is due to the high er
mass flow as well as the higher specific
heat of the gas. In the Cheng cycle (3),
for example, steam injection is significant,
raising the amount of water vapor from
7% in uninjected units to 25%, with a
corresponding increase in the gas turbine
power output from 3.5 to about 5.5 MW.
In summer months the gas turbine
power output drops off, which may not
be tolerable in some plants. Evaporative
cooling or some other form of air cooling can be used in these plants to maintain a low and steady inlet air temperature to the compressor throughout the
year. This results in a constant power
output and steam generation, and
HRSG performance in such units does
not vary much with ambient temperatures. However, this option is
economical only in large gas turbines exceeding, say, 50 MW capacity.
Closing
Closing thoughts
Gas turbine HRSGs have different
performance characteristics and construction features than conventional
steam generators. By understanding
these and relating them to conven tional
steam generators, engineers can generate
steam efficiently.
The key points to remember are as
follows. To determine steam generation
from a given gas turbine, a HRSG
simulation should be performed,
because the HRSG exit gas temperature
cannot be arbitrarily selected (as in a
conventional steam
generator). While evaluating HRSG
steam flow, pinch and approach points
should be selected in the un fired mode.
Fired HRSGs are more efficient than
unfired; hence, cogeneration plants are
more efficient in the fired mode.
Several options for im proving energy
recovery in the HRSG should be
evaluated. Multiple-pres sure steam
generation should be considered to
optimize energy recovery, particularly if
high-pressure steam is generated. Since
extended surfaces are widely used, an
understanding of heat-transfer
characteristics with finned tubes is
desirable. Engineers often make the
mistake of selecting a HRSG based on
surface area alone, which can be
misleading - more surface area does not
always mean more heat transferred.
And finally,
HRSG simulation can help one evaluate plant operating data and compare it
with design data.
CHEMICAL ENGINEERING PROGRESS
AUGUST 1996 •
14